Sunday, May 12, 2019


When a wavefront hits a boundary at vertical incidence, the amount of compressional energy reflected and transmitted is dependent only on the contrast of acoustic impedance- density times compressional velocity- of the rocks at that boundary. But when the incident angle is not 0 degree, the amount of compressional energy reflected of tranmitted depends on the angle of incidence, or source offset, and contrast in densities and shear and compressional velocities. In such cases, the reflection AVo can be measured and analyzed to yield information about lithology and pore fluid through their effects on density and compressional and shear velocities. 

Carrying out a walkaway VSP with the receivers straddling such a boundary allows direct measurement of the variation in amplitude with offset that arises from lithology and fluid properties above and below the reflector. The results can be analyzed for fluid and lithology identification in a wide zone around the well. Formation properties inferred from VSPs can be integrated with those interpreted from well logs and measured directly from cores. In this way the VSP can also provide independent calibration of the same amplitude variation seen across a surface seismic reflection point gather- a gather is thee collection of traces that reflect at the same point, but at different angles, or offsets.

Calibrating the surface seismic AVO data with the VSP AVO response brings added value by:

  • establishing viability of using AVO to map a reservoir.
  • reducing the risk involved with the added cost of AVO studies
  • improving the reliability of AVO interpretations
  • quantitatively assessing the effects of processing on the AVO response.

To establish whether AVO is applicable as an interpretation tool for a particular reservoir, the expected AVO response is usually modeled. This requires knowledge of the model parameters, including shear velocity. Dipole shear sonic logging tools are used to measure shear velocities even where this velocity is slower than the borehole fluid velocity.

However, use of density and velocity log data to model anticipated AVO anomalies has not always succeeded in fully explaining the AVO response observed on surface seismic gathers.

Tuesday, April 9, 2019

Borehole Seismic Data

Seismic surveys in the borehole deliver a high-resolution quantitative measure of the seismic response of the surrounding reservoir. Although these measurements may be used alone to image local features, they may also be tied with well data-logs and cores- and then related to more extensive surface seismic data. Advances in borehole geophysics are helping realize the full potential of existing data to create a sharper image of the reservoir. 

It's a matter of resolution. Surface seismic surveys deliver  one of the few quantitative measurements of reservoir properties away from wells, making the technique central to structural mapping of the entire reservoir volume. However, surface seismic waves cannot resolve features smaller than 30 to 40 ft [9 to 12 m] . On the other hand, logs and cores resolve features on the scale of a few feet down to about 6 inches [15 cm]. Reconciling these two measurement scales to get the optimal picture of the reservoir volume is a problem that has long challenged the industry.

Borehole geophysics has a foot in both the logging and surface camps. From the vantage of the wellbore, seismic data often have higher resolution than their surface seismic counterparts. Depths of each borehole receiver are also known, providing a better tie to the formation properties provided by petrophysical, core and other in-situ measurements and relating them to the 3D seismic volume. 

The idea of locating a receiver downhole and a seismic source at surface is not new. For more than half a century, the check shot has helped to correlate time-based surface seismic surveys with depth-based logs. Check shots check the seismic travel time from a surface shot to receivers at selected depth intervals. Subtraction of times, combined with the depth differences, yields vertical interval velocities and thus relates well depths to surface seismic times. 

In vertical seismic profiles (VSPs), the spacing between downhole geophone levels is considerably closer than for check-shot surveys. VSPs use high-quality full waveforms that include reflection information rather than just the time of first arrivals - or first breaks- to create an image of reflections near the wellbore. Building on this technique, 2D reflection images have been obtained by offset and walkaway surveys with sources and receivers in a variety of configurations that address most reservoir problems.

Yet, despite these and other developments, borehole geophysics has for many years failed to gain the status in reservoir characterization that some industry specialists think it deserves. Now, thanks to improved quality and increased confidence in the match between borehole and surface seismic data, borehole geophysics seems to be moving into an increasingly valued position.

Before examining how borehole seismic data are being used to successfully integrate other data, this article will illustrate how the scope of VSP is broadening through the development of horizontal, 3D and through-tubing techniques.

Broadening the Scope of VSP Applications

In the deviated and horizontal wells of the North Sea,the most common type of borehole seismic survey is the vertical-incidence VSP. These are often called walk-above surveys because, as the geophone is moved along the deviated section of borehole, the source is kept vertically above it, "walking above" the well.  In VSP terms, a horizontal well is an extreme version of a deviated well. Like other VSPs, deviated well surveys may be used for locating the well in the 3D surface seismic volume and assessing the quality of surface seismic surveys. Also, the technique may be employed for measuring lateral velocity variations and for imaging faults and structures below the wellbore. 

The following example of a walk-above VSP was carried out in late 1994, in a North Sea well with a 1.2 kilometer horizontal section. There were two main objectives. The first was to measure a suspected lateral velocity anomaly that may have been creating artifacts in the surface seismic data. The second was to obtain a high-resolution seismic image below the deviated portion of the well. An additional objective was to obtain seismic image in the horizontal part of the well.

Data were collected in ther vertical and deviated portions of the cased well using the conventional wireline-conveyed ASI Array Seismic Imager tool. In the horizontal section, a two-element CSI Combinable Seismic Imager geophone array was run on drillpipe in combination with a cement bond log. By decoupling the sensor module from the body of the CSI tool, the geophones are isolated from noise and distortions created by the drillpipe. 

As with any survey, the desired seismic image is produced using the reflected, or upgoing, wavefield. So the first processing task was to separate downgoing waveforms from upgoing. For walk-above surveys in horizontal wells, this is far from straightforward, since unlike vertical and deviated wells, there is no apparent time difference across the array between the downgoing and the reflected upgoing waves. It is therefore impossible to use conventional techniques to distinguish between reflections and downgoing waves. To improve the image a number of special techniques were used, including:
  • multichannel filtering to attenuate noise and sharpen the desired signal
  • downgoing wavefield subtraction using a long filter length to estimate the downgoing wavefield
  • median filtering techniques to estimate and subtract the energy scattered by faults
  • enhancement of the desired upgoing signal
  • equalization of the reflected wavefield amplitudes from the horizontal and the build up sections.

The final image showed three important features: the two faults marked A and B, which appear where suspected in the reflected image, and the dip of the strata below the well. Formation MicroScanner data acquired during openhole logging were compared with the VSP, confirming the fault locations-seen as chevrons in the VSP - and the apparent dips.

In this case study, VSP processing was performed before Formation MicroScanner data were ready to interpret, and the VSP helped the interpretation by outlining the major features. The two data sets were then interpreted and refined together, providing a more complete description of near-well geology than was otherwise available. The results met the main objectives of the survey and delivered an image below the horizontal section. 

An alternative strategy for acquiring and processing horizontal VSP data exploits the different responses of geophones and hydrophones to differentiate downgoing energy from upgoing energy in horizontal wells. Geophones are clamped to the formation, and sense its motion. In contrast, hydrophones are suspended in the borehole fluid and are sensitive to fluid pressure changes as seismic wave passes in any direction. When the two sensor types show the same signal polarity for a downgoing wave, they show different polarities for the upgoing wave.  By taking the difference between signals received at the two types of sensors - for a signal consisting of a direct pulse followed by a reflected pulse- the direct wave is canceled and the reflection enhanced.

Complications arise from differences in the coupling and impulse responses between geophones and hydrophones. However, this approach has recently been applied in the field, enabling the extraction of related wavefields in a horizontal well and the imaging of reflectors below the receivers.

 3D VSPs

VSP imaging surveys, such as walkaways, have been used for a number of years to image structural complexity away from the borehole. These walkaway profiles are essentially two-dimensional, confined to the vertical plane containing the surface source and the borehole. 

Because of the proximity of the receivers to the target, like all VPSs, these 2D images usually have the advantage of being of higher resolution than their surface seismic counterparts. But, by definition, 2D walkaways don't describe the full volume of the reservoir. Fortunately, the acquisition principle may be extended to cover three dimensions by repeated profiling in parallel lines - in effect, by collecting a series of 2D walkaway surveys similar to marine 3D seismic data acquisition. 

The progression from 2D to 3D in VSP surveys is similar to the progression in the surface seismic technique , and offers equivalent benefits. Thus, 3D VSPs allow high resolution imaging to augment surface 3D surveys and make it possible to obtain  images beneath surface obstacles, such as platforms, and near-surface obstructions, such as shallow gas zones. In addition, because the acquisition conditions and processing steps of VSP surveys are accurately reproducible, 3D VSP opens up the possibility of time-lapse, or 4D, seismic surveying. 

However, progressing from 2D to 3D substantially increases the need for planning and logistics control. Similarly, the processing requirements are almost an order of magnitude greater. 

The first 3D VSP survey was run in 1987 in the Adriatic Sea Brenda field, operated by AGIP. Since then, there have been two 3D VSP surveys in the Norwegian Ekofisk field for Phillips Norway- where a large gas plume over the center of the structure prevents imaging using conventional 3D surface seismic techniques. Other Norwegian surveys probe the Eldfisk and Oseberg fields. 

In the UK North Sea, a 41-line, 3D walkaway VSP survey has been carried out in Shell Expro's Brent field. In this case, the aim was to acquire a survey with improved resolution compared with the 3D surface seismic survey. The image was then be used to produce an accurate structural map to aid the planning of horizontal development wells in the Brent slump- a crestal zone of complex faulting and collapse which contains a significant portion of the field's remaining oil reserves. 

The survey was executed from a well with a trajectory that allowed positioning the geophones to give three-dimensional illumination of the slump zone. The receivers consisted of five shuttles with fixed triaxial sensors, clamped 2000 ft [606 m] above the target during the entire survey. Once in the well but prior to shooting, the coupling between each of the shuttles and the formation was evaluated using internal shakers to ensure distortion-free data.

The seismic source consisted of a cluster of three 150 in 3 sleeve guns. To supply sufficient gas for 41 lines of 200 shots per line, four 5100 cubic meter nitrogen-filled tube skids were used. Simultaneously with the downhole data acquisition, each shot location on the surface was recorded using two differential GPS navigation system. 

To make the survey cost-effective, it was vital to minimize time spent acquiring data -every extra minute per sail line meant an additional 41 minutes of rig time. For example, to reduce the time the vessel took to maneuver between lines, a strategy was devised to wrap each line efficiently into the next. In the end, the data were acquired within the planned survey time of two and a half days, including a conventional VSP.

The 3D processing involves an extension of methods already developed for 2D walkaways-data preparation and navigation check, triaxial projection, wavefield separation, deconvolution and migration. 

In this case, the processing consisted of separate preparation and processing of all 41 lines up to the deconvolution stage. Then all 41 reflected energy profiles were accessed by the 3D VSP migration algorithms to place the reflections correctly in space.

The successful processing of these surveys required an experienced geophysicist with strong interpretative skills to make the correct decisions at each stage of the processing -for example, to ensure that all possible questions related to the influence of data quality had been resolved. These skills ensured that the image was interpreted in terms of reservoir structure without processing artifacts.

The migration process requires the computation of raypaths from each source and every receiver to every reflection point in the subsurface. The rays are traced through a velocity model of the subsurface that can vary in complexity between flat layers ( a 1D layercake) to complex structures in 2D or 3D.

For simple structures , a layercake velocity model, which reduces computation time, is sufficient.  However, using this model in more complex subsurface may lead to erroneous positioning of reflections and the incorrect focusing of real events. More complex velocity model increase the number of ray-trace computations required, but are better able to position reflected events and focus the wave energy.

The Brent structure varies in the dip direction but changes very little along strike. Consequently, the velocity model is more complex than a plain 2D model but not as complex as a full 3D model; the structure varies in one horizontal direction and is extruded into the other horizontal dimension to form a so-called "2.5D" model. In this, the volume may be thought of as filled with an infinite number of 2D sections. This allowed computational efficiency due to symmetry and ensured a close match with the actual Brent structure.

Shell concluded that the Brent 3D VSP improved vertical resolution and significantly improved horizontal resolution- resolving features on the order of 100 to 150 ft [ 30 to 45 m] as opposed to the original 3D surface seismic resolution of 200 to 300 ft [60 to 90 m] . The interpretation of the slump features has confirmed conclusions reached independently , demonstrating the technique's potential and reducing the risk of a proposed new 3D surface survey.

 Through-Tubing VSPs

The third application broadening the scope of borehole geophysics is the VSP through tubing. Thanks to hardware developments, cost-effective VSPs can be run in mature fields that promise significant economic benefits

Traditionally, borehole seismic surveys are acquired in exploration wells when they are drilled. However, in older fields, borehole seismic information is often needed to aid the reservoir engineer in areas where no new wells are planned, or to plan a new well. Now a slim seismic receiver may be deployed by a simple masted logging truck to acquire borehole seismic data through production tubing and inside casing during workover or while the well is still on production. This reduces acquisition costs and makes surveys in multiple wells possible during the same mobilization. 

In this way, a full range of borehole surveys may be carried out and the data may be used to tie log and production information to new 3D surface seismic surveys being run in older producing fields.

The slim seismic tool has a 1 11/16- inch outside diameter and may carry one single-axis geophone group or three orthogonally mounted accelerometers.The mechanicallytt actuated anchor has a maximum opening of 7 in. [17 cm] . The tool is adapted for operation with a monocable wireline and through-wellhead pressure fittings. This allows for operations in producing wells with surface pressure. As with any system, a range of seismic information may be obtained in vertical or deviated wells, from check shots to walkaway VSP images.

For example, an offest VSP survey was acquired through tubing and through casing in an abandoned wwell in an inland shallow water field in south Lousiana, USA, using a marine vibroseis unit as a source to acquire high-resolution data. The offset VSP survey was designed to confirm the location of a low-angle fault-indicated by logs-which could not be seen on the surface seismic images. The fault's orientation was needed to reduce the risk of an infill development well and was easily spotted using the offset VSP image.

Using Borehole Geophysics to Integrate Data

A the heart of developments to improve data integration is the recognition of the complementary nature of some measurements. Perhaps the best example of this is the relationship between sonic logs and seismic data. In these two measurements, the physical interaction with the reservoir is the same, but at a different scale of resolution. The sonic tool measures formation compressional slowness, which is dependent on many factors, including the formation porosity and lithology. 

Compressional slowness combined with density provides the one-dimensional acoustic impedance of the formation, the same property that underlies seismic reflections. 

But seismic waves are sensitive only to relative changes in acoustic impedance, unlike sonic slowness measurements, which sample absolute values. Therefore, acoustic impedances from logs provide sufficient information to model most, but not all features of the seismic response. The total travel time measured by sonic logs is a required contribution to the bulk response of the low-frequency surface seismic surveys. Then, synthetic seismograms may be constructed and the response of the formation simulated by altering parameters such as porosity, fluid type and lithology. The synthetics can be used to interpret real data.

Although the scope of VSPs is expanding, the wealth of information relating to lithology, fluid contacts and the seismic responses that they produce is not always used to its fullest extent. This is particularly true when it comes to evaluating and improving the information content of surface seismic data. Now, existing technologies are being used in new ways to provide additional direct quantitative mesurements of the seismic response of the reservoir adjacent to wells.

The next two examples clearly indicate how the integration of all available data may improve understanding of the reservoir. The first example looks at how structural and stratigraphic interpretations may be improved. The second shows how reflection amplitude variation with offset (AVO) from VSPs may be used to calibrate surface seismic AVO.

Morgan's Bluff

In the Morgan's Bluff field of Orange County, Texas, USA, the operator IP Petroleum needed to map the shale edge of its Hackberry reservoir to design a secondary reservoir program.

Substantial existing 2D surface seismic data did not adequately image the reservoir. Therefore, vertical incidence and offset VSPs were shot within a production well. These results were combined with logs and geologic information to map the edge of  the shale. Further, the surface seismic lines were reinterpreted, resulting in an extensive remapping of the Hackberry sand.

The aim was to drill a sidetrack from the shut-in producing Well 8 toward the adjacent Well 10, depending on the exact reservoir boundary, to be determined using the VSP - the Hackberry sand was originally mapped on the strike line that runs through both of these wells.

First , the feasibility of this plan was tested and detailed survey models were constructed using structure maps, log data from the two wells and velocity data from a third well. Borehole seismic data shot in 1986 in the central part of the field were used to construct the general velocity model. In Well 8, sonic logs were available to about 8000 ft , and only nuclear and resistivity logs from there to total depth. A pseudosonic log was constructed from these logs and compared to the velocities from the VSP survey. A synthetic offset VSP was then generated using the same wavefield separation, deconvolution and migration processing to be used with the real data. 

Two scenarios were forward modeled: a gradual shaling out and an abrupt, or faulted, sand termination. From this it was agreed that in either case the shale boundary should be interpretable to within 100 ft using the offset VSP sections, and the go-ahead for the survey was given. Additionally, a second offset VSP to the west of well 8 was designed to confirm the interpretation. A VSP was also to be carried out in Well 8 to build an updated velocity model for migration.

The three downhole surveys were acquired with sources located 4000 ft [1212 m] to the west-southwest, 4300 ft [1300 m] to the southwest and 400 ft [121 m] to the east-southeast. An eight level downhole receiver system was deployed to record 110 levels at 50 ft [15 m] spacing from 8500 to 3000 ft [2575 m to 909 m]. Across each interval, the top and bottom shuttles were overlapped to check for any source amplitude, signature or phase changes during the survey.

Following a standard processing sequence using a flat-layer velocity model and some small velocity changes to match the model to the observed transit times, each of the offset VSPs was migrated. Logs from Well 8 were correlated with the offset VSPs.

Monday, March 25, 2019

Nuclear Magnetic Resonance Imaging

Although well logging has made major advances over the last 70 years, several important reservoir properties are still not measured in a continous log. Among these are producibility, irreducible water saturation and residual oil saturation. Nuclear magnetic resonance (NMR) logging has long promised to measure these, yet it is only recently that technological developments backed up by sound research into the physics behind the measurements show signs of fulfilling that promise. 

 For nearly 70 years, the oil industry has relied on logging tools to reveal the properties of the subsurface. The arsenal of wireline measurements has grown to allow unprecedented understanding of hydrocarbon reservoirs, but problems persist: a continuous log of permeability remains elusive, pay zones are bypassed and oil is left in the ground. A reliable nuclear magnetic resonance (NMR) measurement may change all that. This article reviews the physics and interpretation of NMR techniques, and examines field examples where NMR logging has been successful. 

 Some Basics

Nuclear magnetic resonance refers to a physical principle- response of nuclei to a magnetic field. Many nuclei have a magnetic moment- they behave like spinning bar magnets. These spinning magnetic nuclei can interact with externally applied magnetic fields, producing measurable signals.

 For most elements the detected signals are small. However, hydrogen has a relatively large magnetic moment and is abundant in both water and hydrocarbon in the pore space of rock. By tuning NMR logging tools to the magnetic resonant frequency of hydrogen, the signal is maximized and can be measured. 

The quantities measured are signal amplitude and decay. NMR signal amplitude is proportional to the number of hydrogen nuclei present and is calibrated to give porosity, free from radioactive sources and free from lithology effects. However, the decay of the NMR signal during each mesurement cycle- called the relaxation time- generates the most excitement among the petrophysical community.

Relaxation times depend on pore sizes. For example, small pores shorten relaxation times- the shortest times corresponding to clay-bound and cappilary-bound water. Large pores allow long relaxation times and contain the most readily producible fluids. Therefore the distribution of relaxation times is a measure of the distribution of pore sizes- a new petrophysical parameter. Relaxation times and their distribution may be interpreted to give other petrophysical parameters such as permeability, producible porosity and irreducible water saturation. Other possible applications include capillary pressure curves, hydrocarbon identification and as an aid to facies analysis.

Two relaxation times and their distributions can be measured during an NMR experiment. Laboratory instruments usually measure longitudinal relaxation time, T1 and T2 distribution, while borehole instruments make the faster measurements of tranverse relaxation time, T2 and T2 distribution. In the rest of this article T2 will mean tranverse relaxation time. 

NMR Applications and Examples

The T2 distribution measured by the Schlumberger CMR Combinable Magnetic Resonance tool, described later, summarizes all the NMR measurements and has several petrophysical applications:
  • T2 distibution mimics pore size distribution in water-saturated rock
  • the area under the distribution curve equals CMR porosity
  • permeability is estimated from logarithmic-mean T2 and CMR porosity
  • empirically derived cutoffs separate the T2 distribution into areas equal to free-liquid porosity and irreducible water porosity.

Application and interpretation of NMR measurement rely on understanding the rock and fluid properties that cause relaxation. With this foundation of the mechanisms of relaxation, the interpretation of T2 distribution becomes straightforward.

T2 Distribution - in porous media, T2 relaxation time is proportional to pore size.  The observed T2 decay is the sum of T2 signalss from hydrogen protons, in many individual pores, relaxing indepedently. The T2 distribution graphically shows the volume of pore fluid associated with each value of T2, and therefore the volume associated with each pore.

Signal processing techniques are used to transform NMR signals into T2 distributions. Processing details are beyond the scope of this article.

In an example taken from a carbonate reservoir, T2 distributions from X340 ft to X405 ft are biased towards the high end of the distribution spectrum indicating large pores. Below X405 ft, the bias is towards the low end of the spectrum, indicating small pores. This not only provides a qualitative feel for which zones are likely to produce, but also helps geologists with facies analysis.

Lithology-independent porosity- Traditional calculations of porosity rely on borehole measurements of density and neutron porosity. Both measurements require environmental corrections and are influenced by lithology and formation fluid. The porosity derived is total porosity, which consists of producible fluids, capillary-bound water and clay-bound water. 

However, CMR porosity is not influenced by lithology and includes only producible fluids and capillary-bound water. This is because hydrogen in rock matrix and in clay-bound water has sufficiently short T2 relaxation times that the signal is lost during the dead time of the tool. 

An example in a clean carbonate formation compares CMR porosity with that derived from the density tool to show lithology independence. The lower half of the interval is predominantly limestone, and density porosity, assuming a limestone matrix , overlays CMR porosity. At X935 ft, the reservoir changes to dolomite and density porosity has to be adjusted to a dolomite matrix to overlay the CMR porosity. If the lithology is not known or if it is complex, CMR porosity gives the best solution. Also, no radioactive sources are used for the measurement, so there are no environmental concerns when logging in bad boreholes. 

Permeability -perhaps the most important feature of NMR logging is the ability to record a real-time permeability log. The potential benefits to oil companies are enormous. Log permeability measurements enable production rates to be predicted, allowing optimization of completion and stimulation programs while decreasing the cost of coring and testing.

Permeability is derived from empirical relationships between NMR porosity and mean values of T2 relaxation times. These relationships were developed from brine permeability measurements and NMR measurements made in laboratory on hundreds of different core samples. The following formula is commonly used:

A cored interval of a well was logged using the CMR tool. The value of C in the CMR permeability model was calculated from core permeability at several depths. After calibration CMR permeability was found to overlay all core permeability points over the whole interval. Over the zone XX41 m to XX49 m the porosity varied little. However, permeability varied considerably from a low of 0.07 md at XX48 m to a high of 10 md at XX43 m. CMR permeability also showed excellent vertical resolution and compared well to that of core values. The value of C used for this well will be applied to subsequent CMR logs in this formation enabling the oil company to reduce coring costs.

Free-fluid index - The value of free-fluid index is determined by applying a cutoff to the T2 relaxation curve. Values above the cutoff indicate large pores potentially capable of producing, and values below indicate small pores containing fluid that is trapped by capillary pressure, incapable of producing.  

 Many experiments have been made on rock samples to verify this assumption. T2 distributions were measured on water-saturated cores before and after they had been centrifuged in air to expel the producible water. The samples were centrifuged under 100 psi to simulate reservoir capillary pressure.  Before centrifuging, the relaxation distribution corresponds to all pore sizes. It seems logical to assume that during centrifuging the large pore spaces empty first. Not surprsingly, the long relaxation times disappeared from the T2 measurement. 

Observations of many sandstone samples showed that a cutoff time of 33 msec of T2 distribuitons would distinguish between free-fluid porosity and capillary-bound water.  For carbonates, relaxation times tend to be three times longer and a cutoff of 100 msec is used. However, both these values will vary if reservoir capillary pressure differs from the 100 psi used on the centrifuged samples. If this is the case, the experiments may be repeated to find cutoff times appropriate to the reservoir. 

In a fine-grained sandstone reservoir example, interpretation of conventional log data showed 70 to 80% water saturation across a shaly sandstone formation. However, on the CMR log most of the T2 distribution falls below the 33-msec cutoff indicating capillary-bound water. Interpretation including CMR data showed that most of the water was irreducible. The well has since been completed producing economic quantities of gas and oil with a low water cut. The water cut may be estimated from the difference between residual water saturation and water saturation from resistivity logs.

 In another example, but this time in a complex carbonate reservoir, the oil company was concerned about water coning during production. CMR log data showed low T2 values below X405 ft indicating small pore sizes. Applying the carbonate cutoff of 100 msec showed that nearly all the water was irreducible, which allowed additional perforation. To date no water coning has occured.

Values for cutoffs can also be tailored to particular reservoirs and help with facies analysis, as in the case of the Thamama group of formations in Abu Dhabi Oil Company Mubarraza field offshore Abu Dhabi, UAE. In this field, classical log interpretation showed water saturation of 10 to 60%. However, some zones produced no water, making completion decisions difficult. Permeability also varied widely even though porosity remained almost constant.  Laboratory measurements were performed on cores to determine whether NMR logging would improve log evaluation. 

 Cores showed a good deal of microporosity holding a large volume of capillary-bound water. Free-fluid porosity was found in the traditional way by centrifuging the water-saturated cores. For this reservoir, however, capillary pressure was known to be 25 psi, so the core samples were centrifuged accordingly. This showed that NMR measurements could provide a good estimate of nonproducing micropores using a T2 cutoff of 190 msec. In addition, permeable grainstone facies could be distinguished from lower-permeability packstones and mudstones with a cutoff of 225 msec.  

Additional Applications

Borehole NMR instruments are shallow-reading devices. In most cases, they measure formation properties in the flushed zone. This has some advantages as mud filtrate properties are well-known and can be measured at the wellsite on surface. When fluid loss during drilling is low, as in the case of low-permeability formations, hydrocarbons may also be present in the flushed zone. In these cases NMR tool may measure fluid properties such as viscosity and so distingish oil from water. 

A published example of the effects of hydrocarbon viscosity comes from Shell's North Belridge diatomite and Brown Shale formations, Bakersfield, California, USA. Both CMR logs and laboratory measurements on cores show two distinct peaks on the T2 distribution curves. The shorter peak, at about 10 msec, originates from water in contact with the diatom surface. The longer peak, at about 150 msec, originates from light oil.  The position of the oil peak correlates roughly with oil viscosity. The area under this peak provides an estimation of oil saturation.

 T2 distribution measurements were also made on crude oil samples having viscosities oof 2.7 cp to 4300 cp. Highly viscous oils have less mobile hydrogen protons and tend to relax quickly. The CMR log showed the T2 oil peak and correctly predicted oil viscosity. It also showed that the upper 150 ft of the diatomite formation undergoes a transition to heavier oil.

Capillary pressure curves, used by reservoir engineers to estimate the percentage of connate water, may also be predicted from T2 distributions. Typically these curves- plots of mercury volume versus pressure- are produced by injecting mercury into core samples. Under low pressure the mercury fills the largest pores and, as pressure increases, progressively smaller pores are filled. The derivate of the capillary pressure curve approximates the T2 distribution. Some differences in shape are expected as mercury injection measures pore throat sizes, whereas NMR measurements respond to the size of pore bodies.

 Other applications and techniques are likely to follow with more complex operations that might involve comparing logs run under different borehole conditions. For example, fluid may be injected into the formation that is designed to kill the water, so that residual oil saturation may be measured. 

Function of a Pulsed Magnetic

The CMR tool is the latest generation Schlumberger NMR tool. The measurement takes place entirely within the formation, eliminating the need to dope mud systems witth magnetite to kill the borehole signal- a big drawback with the old earth-field tools. It uses pulsed-NMR technology, which eliminates the effects of nonuniform static magnetic fields and also increases signal strength. This technology, along with the sidewall design, makes the tool only 14 ft long and readily combinable with other borehole logging tools. 

The skid-type sensor package , mounted on the side of the tool, contains two permanent magnets and a transmiter-receiver antenna. A bowspring ecentralizing arm or powered caliper arm- if run in combination with other logging tools- forces the skid against the borehole wall, effectively removing any upper limit to borehole size. 

An important advantage of the sidewall design is that the effect of conductive mud, which shorts out the antenna on mandrel-type tools, is greatly reduced. What little effect remains is fully corrected by an internal calibration signal. Another advantage is that calibration of NMR porosity is simplified and consist of placing a bottle of water against the skid to simulate 100% porosity. T2 properties of mud filtrate samples required for interpretations corrections- may also be measured at the wellsite in a similar fashion. Finally, the design enables high- resolution logging- a 6-inch long measurement aperture is provided by a focoused magnetic field and antenna.

Two permanent magnets generate the focused magnetic field, which is about 1000 times stronger than the Earth's magnetic field. The magnets are arranged so that the field converges to form a zone of constant strength about one inch inside the formation. NMR measurements take place in this region.  

 By design, the area between the skid and the measurement volume does not contribute to the NMR signal. Coupled with skid geometry, this provides sufficient immunity to the effects of mudcake and hole rugosity. The rugose hole effect is similar to that of other skid-type tools such as the Litho-Density tool.

The measurement sequence starts with a wait time of about 1.3 sec to allow for complete polarization of the hydrogen protons in the formation along the length of the skid. Then the antenna typically transmits a train of 600 magnetic pulses into the formation at 320-msec intervals. Each pulse induces an NMR signal-spin echo-from the aligned hydrogen protons. The antenna also acts as a receiver and records each spin echo amplitude. T2 distribution is derived from the decaying spin echo curve, sometimes called the relaxation curve. 


Thursday, March 21, 2019

Controlling Fluid Loss

A portion of the fluid pumped during a fracturing treatment filters into the surrounding permeable rock matrix. This process, referred to as fluid leakoff or fluid loss, occurs at the fracture face.  The volume of fluid lost does not contribute to extending or widening the fracture. Fluid efficiency is one parameter describing the fluid's ability to create the fracture. As leakoff increases , efficiency decreases. Excessive fluid loss can jeopardize the treatment, increase pumping costs and decrease post-treatment well performance. 

Typically, particulates or other fluid additives are used to reduce leakoff by forming a filter cake- termed an external cake- on the surface of the fracture face. Acting together with the polymer chains, the fluid-loss material blocks the pore throats, effectively preventing invasion into the rock matrix.

 This approach has been applied successfully for decades to low-permeability (< 0.1 md) formations in which polymer and particulate sizes exceed those of the pore throats. In high permeability reservoirs, however, fluid constituents may penetrate into the matrix, forming a damaging internal filter cake. This behavior has prompted mechanistic studies to determine the impact on fracturing treatment performance.

 Classic fluid-loss theory assumes a two-stage, static - or nonflowing-process. As the fracture propagates and fresh formation surfaces are exposed, an initial loss of fluid, called spurt, occurs until an external filter cake is deposited. Once spurt ceases, pressure drop through the filter cake controls further leakoff. For years, researchers have developed fluid-loss control additives under nonflowing conditions based on this theory.

 The conventional assumptions, however, neglect critical factors found under actual dynamic - or flowing- conditions present during fracturing, including the effects of shear stress on both external and internal filter cakes and how fluid-loss additives move toward the fracture face. In high-permeability formations, with an internal filter cake present, most of the resistance to leakoff occurs inside the rock, leaving the external cake subject to erosion by fluid.

 Analysis of fluid loss under dynamic conditions relates external cake thickness to the yield stress of the cake at the fluid interface and the shear stress exerted on the cake by the fluid. These, in turn, depend on the physical properties of the cake and the rheological properties of, and shear rate induced in , the fluid. Whether an external filter cake forms, grows, remains stable or erodes depends on the way these parameters vary and interact over time and spatial orentation.

Similarly, the effectiveness of additives to control fluid depends on two factors: their ability to reach the fracture face quickly and their ability to remain there. The former is governed by the drag force exerted on the particles and the latter by the shear force exerted on them. The larger the ratio of drag to shear , the greater the chance that the particles will remain on the surface. A greter leakoff flux to the wall, smaller particle dimensions and a lower shear rate favor sticking. Promoting higher leakoff for better additive placement seems directly at odds with controlling fluid loss! However, in practice, higher initial leakoff can yield greter overal fluid efficiency. 

To confirm the controlling mechanisms, dynamic fluid-loss tests were conducted  using a slot-flow geometry, determined to be the simplest representation of what occurs in a fracture. To completly describe the process, computer-controlled equipment was constructed to prepare and test fluids under dynamic conditions, subjecting them to the temperature and shear histories found in a fracture. Cores of various lengths were used in the tests to simulate a fracture segment at a fixed distance from the wellbore. As the fracture tip passes a spesific point, spurt occurs and the shear rate reaches maximum. Then, as the fracture widens, the shear stress decreases. In the test apparatus, this is stimulated by decreasing the flow rate with time. Pressure sensors along the core monitor the progress of the polymer front.

Laboratory tests show that , for comparable fluids and rocks with permeabilities of up to 50 md, fluid loss is greater under dynamic conditions than static conditions. Further, examining the impact of shear stress and permeability on the magnitude of fluid loss and the effectiveness of leakoff control additives in high-permeability formations led to five key conclusions.

First, high shear rates can prevent the formation of an external filter cake and result in higher than expected spurt. Second, an internal filter cake controls fluid loss, especially near the fracture tip. Third, the effectiveness of fluid-loss additives increases with formation permeability and decreases with shear rate and fluid viscosity. Fourth, reducing fluid loss means reducing spurt, particularly under high shear conditions and in high-permeability formations. 

The effect of shear depends on the type of fluid and the formation permeability. Typically, above a threshold shear level, no external cake is formed. The magnitude of fluid loss is dependent on the type of polymer and whether it is crosslinked. If the permeability is high enough and the fluid structure degrades with shear, polymer may be able to penetrate the rock matrix.

Dynamic test revealed that commonly used additives were less effective in controlling fluid loss than static test had previously indicated. Also, a direct link between fluid efficiency and shear rate was demonstrated. The higher the fraction of fluid lost under high shear early in the treatment, the higher the total leakoff volume and the lower the efficiency.


Sunday, March 10, 2019

Advance Fracturing Fluids Improve Well Economics

The oil and gas industry has witnessed a revolution in fluids technology for hydraulic fracturing. Starting in the mid 1980s, focused research led to major improvements in the performance of well stimulation fluids. Today, new additives and fluids are extending these capabilities and providing innovative solutions to nagging problems. The results are more efficient and cost-effective treatments for enhancing well production.

 Hydraulic fracturing is one of the oil and gas industry's most complex operations. This technique has been applied worldwide to increase well productivity for nearly 50 years. Fluids are pumped into a well at pressures and flow rates high enough to split the rock and create two opposing cracks extending up to 1000 ft [ 305 m] or more from either side of the borehole. Sand or ceramic particulates, called proppant, are carried by the fluid to pack the fracture, keeping it open once pumping stops and pressure decline.

What defines a successful fracture? It is one that: 

  • is created reliably and cost-effetively
  • provides maximum productivity enhancement 
  • is conductive and stable over time.  

The Rock, the mechanics and the Fluid

Historically, fracturing has been applied primarily to low-permeability- 0.1 to 10 md-  formations with the goal of producing narrow, conductive flow paths that penetrate deep into the reservoir. These less restrictive linear conduits replace radial flow regimes and yield a several-fold production increase. For large-scale treatments, as many as 40 pieces of specialized equipment, with a crew of 50 or more, are required to mix, blend and pump the fluid at more than 50 barrels per minute (bbl/min). Pumping may last eight hours with 1,000,000 gal of fluid and 2,000,000 to 4,000,000 lbm of propant placed in the fracture.

Until recently, treatments were performed almost exclusively on poor producing wells (often to make them economically viable). In the early 1990s, industry focus shifted to good producers and wells with potential for greater financial return. This, in turn, meant an increased emphasis on stimulating high-permeability formations.

The major constraint on production from such reservoirs is formation damage, frequently remedied by matrix acidizing treatments. But acidizing has limitations, and fracturing has found an important niche. The objective in highly permeable foormations is to create short, wide fractures to reach beyond the damage. This is often accomplished by having the proppant bridge, or screen out, at the end, or tip. of the fracture early in the treatment. This "tip screenout" technique is the opposite of what is desired in low-permeability formations  where the tips is ideally the last area to be packed.

 Why the different approach? The answer is found in the relationship between fracture length and the permeability contrast between the fracture and the formation. Where the contrast is large, as for low-permeability reservoirs, longer fractures provide proportionally greater productivity. Where the contrast is small, as in high-permeability formations, greater fracture length provides minimal improvement. Fracture conductivity is, however, directly related to fracture width. Using short- about 100-ft [30 m] - and wide fractures can prove beneficial.

High-permeability formation treatments are on a far reduced scale. Only a few pieces of blending and pumping equipment are required, and pumping times are typically less than one hour, and often only 15 minutes. Fluid is pumped at 15 to 20 bbl/min with a total volume of 10,000 to 20,000 gal and total proppant weight of about 100,000 lbm. This technique has been successful in the North Sea, Middle East, Indonesia, Canada and Alaska, USA.

While fracturing treatments vary widely in scale, each requires the successful integration of many disciplines and technologies, regardless of reservoir type. Rock mechanics experiments on cores, specialized injection testing and well logs provide dat on formation properties. Sophisticated computer software uses these data , along with fluid and well parameters, to simulate fracture initiation and propagation. These results and economic criteria define the optimum treatment design. Process-controlled mixing, blending and high-pressure pumping units execute the treatment. Monitoring and recording devices ensure fluid quality and provide permanent logs of job results. Engineers tracking the progress of the treatment use graphic displays that plot actual pumping parameters against design values to facilitate real-time decision making. Production simulators compare treatment results with expectations, providing valuable feedback for design of the next job.

At the heart of this complex process is the fracturing fluid. The fluid, usually water based, is thickened with high molecular weight polymers, such as guar or hydroxyproply guar. It must be chemically stable and sufficiently viscous to suspend the propant while it is sheared and heated in surface equipment, well tubulars, perforations and the fracture. Otherwise, premature settling of the proppant occurs, jeopardizing the treatment.  A suite of specially designed chemical additives imparts important properties to the fluid. Crosslinkers join polymer chains for greater thickening, fluid-loss agents reduce the rate of filtration into the formation and breakers act to degrade the polymer for removal before the well is placed on production.

The fracture is created by pumping a series of fluid and proppant stages. The first stage , or pad, initiates and propagates the fracture but does not contain proppant. Subsequent stages include proppant in increasing concentrations to extend the fracture and ensure its adequate packing.

Fracturing fluid technology has also developed in stages. Early work focused on identifying which polymers worked best and what concentrations gave adequate proppant transport. Then, research on additives to fine-tune fluid properties hit high gear.

In the past ten years, a more productive research direction has emerged. Oil companies, service companies and polymer manufacturers have concentrated on the basic physical and chemical mechanisms underlying the behavior of fracturing fluids in an attempt to find improved approaches to fluid design and use. This initiative has led to major advances , including higher-performing polymers, simpler fluids, multifunctional additives and continuous, instead of batch, mixing. These developments have had a significant , beneficial impact on the industry.

Recent innovations are extending the state of art in four areas:
  • controlling fluid loss to increase fluid efficiency
  •  extending breaker technology to improve fracture conductivity
  • reducing polymer concentration to improve fracture conductivity
  • eliminating proppant flowback to stabilize fractures.